Composition and method for removal of carbonylsulfide from acid gas containing same

ABSTRACT

Novel solvent composition for selective removal of COS from a gas stream containing same, said composition comprising a) at least one polyalkylene glycol alkyl ether of the formula (I) or 1,3-dimethyl-3,4,5,6-tetrahydro-2(1H)-pyrimidinone or a mixture of N-formylmorpholine and N-acetylmorpholine Wherein R 1  is an alkyl group having from 1 to 6 carbon atoms; R 2  is hydrogen or an alkyl group having from 1 to 4 carbon atoms; Alk is an alkylene group, branched or unbranched, having from 2 to 4 carbon atoms, and n is from 1 to 10; and b) at least one alkanolamine compound of the formula (II) or at least one piperazine compound of formula (III) wherein R 3  is hydrogen, an alkyl group having from 1 to 6 carbon atoms, or the R 4 OH group; R 4  is a branched or unbranched alkylene group having from 1 to 6 carbon atoms; R 5 , independently in each occurrence, is hydrogen or an hydroxyalkyl group having from 1 to 4 carbon atoms; and R 6  is hydrogen, an alkyl group having from 1 to 6 carbon atoms or an hydroxyalkyl group having from 1 to 4 carbon atoms.
 
R 1 O—(Alk-O) n —R 2   (I)
 
R 3 NHR 4 OR 6   (II)

CROSS-REFERENCE TO RELATED APPLICATION

This application is a 371 of PCT/US2004/007453 filed Mar. 11, 2004, which claims the benefit of U.S. Provisional Application Serial No. 60/456,354, filed Mar. 21, 2003.

The present invention relates to an improved composition for selective removal of carbonyl sulfide (COS) with minimal absorption of carbon dioxide (CO₂) from an acid gas containing COS and CO₂, and also to a method for selective removal of COS from an acid gas containing COS and CO₂ using this improved composition.

Natural and synthesis gas streams, derived from natural gas reservoirs, petroleum or coal, often contain a significant amount of carbonyl sulfide (COS) in addition to other impurities such as carbon dioxide (CO₂), hydrogen sulfide (H₂S), sulfur dioxide (SO₂), carbon disulfide (CS₂), and mercaptans. Various compositions and processes for removal of acid gases, including COS, from a gas containing same are known and described in the literature.

Certain physical solvents have been widely used for the selective removal of H₂S from gas streams containing H₂S, CO₂ and optionally, other components. For example, dialkyl ethers of polyalkylene glycols are commonly specified for this purpose. Typical of the numerous disclosures of such solvents in the art is European Patent Application No. EP 0770420 A2 and U.S. Pat. Nos. 3,737,392; 3,824,766; 3,837,143; 4,044,100; 4,336,233; 4,581,154; 4,741,745; and 4,946,620, among others. According to such references, it is well known that the solubility of H₂S in these glycols is much higher than the solubility of CO₂. This difference in solubility forms the basis for the selective removal of H₂S by glycol ethers and other physical solvents. Unfortunately, the solubility of COS in most physical solvents is not very different from the solubility of CO₂. Hence, selective removal of COS or COS and H₂S from gas streams containing CO₂ and optionally other components, has proved difficult.

Certain tertiary alkanolamines (methyldiethanolamine and triethanolamine for example) have been widely used for the selective removal of H₂S from gas streams which also contain CO₂. Users of these amines exploit the rapid reaction with H₂S and the slow reaction with CO₂ to allow selective removal of H₂S. Unfortunately, the reaction of these amines with COS is about 100 times slower than the reaction with CO₂. Hence, tertiary amines are relatively ineffective at separating COS or COS and H₂S from CO₂ containing streams.

Certain primary and secondary amines (monoethanolamine, diethanolamine, methylethanolamine, aminoethoxy ethanol, piperazine for example) have been widely used for the simultaneous removal of H₂S and CO₂. These amines react rapidly with both H₂S and CO₂ and are well suited for simultaneous removal of H₂S and CO₂. Although the reaction of COS with these amines is also about 100 times slower than the reaction with CO₂, appreciable amounts of CO₂ and COS can be removed. Unfortunately, since COS reacts much more slowly with these amines than does CO₂, selective removal of COS or COS and H₂S with primary or secondary amines has proved difficult.

The selective removal of COS or COS and H₂S from gas streams containing CO₂ and optionally other components has proved difficult with both physical and chemical solvents. However, in a number of conventional hydrocarbon processing techniques, it is desirable or necessary to remove COS down to few parts per million (ppmv) for several reasons, such as catalyst sensitivity to COS in subsequent operations and statutory or contract requirements regarding sulfur content in product or waste gas streams. The presence of COS has also been identified as the cause of degradation reactions in several commercial processes for acid gas removal. However, in many cases it is neither necessary nor desirable to remove CO₂ from gaseous mixtures.

Various solvent compositions and methods are known for selective removal of COS and H₂S from gaseous mixtures containing same and other acidic gases such as CO₂.

U.S. Pat. No. 3,989,811 (Hill) discloses a multi-step process for removal of acid gases, that is, H₂S, CO₂, and sulfur containing compounds including CS₂, COS, and various mercaptans from sour gases. In this multi-step process, H₂S, CO₂ and COS are absorbed in a nonselective alkanolamine. The regenerated acid gases are then contacted with a selective amine to produce an H₂S rich stripper off gas and a low pressure CO₂ rich stream. Suitable alkanolamines include methyldiethanolamine, triethanolamine, or one or more dipropanolamines, such as di-n-propanolamine or diisopropanolamine. The preferred absorbent for treatment of COS containing gas streams also contains a significant amount of a tetramethylene sulfone (the unsubstituted compound is known as sulfolane). In principle, selective removal of COS and H₂S from the original sour gas stream could be achieved if the CO₂ rich product stream were recompressed and combined with the main treated gas stream. However, the capital and operating costs associated with requiring two absorbers, two strippers and compression of the CO₂ stream would weigh against this option, assuming a less costly alternative can be found.

U.S. Pat. No. 4,482,529 (Chen et al.) discloses a single step process for the selective removal of COS from a gas stream containing CO₂. Small amounts of bicyclo tertiary amine are added to a physical solvent already known to be selective for H₂S in the presence of CO₂. According to the invention, addition of the bicyclo tertiary amine encourages hydrolysis of the COS to H₂S and CO₂. The net effect is to improve the absorption of COS without substantially increasing the absorption of CO₂. Applicable physical solvents include SELEXOL™ solvent (a blend of polyethylene glycol dimethyl ethers sold by Union Carbide Corporation under the trademark SELEXOL), sulfolane, methanol and others.

U.S. Pat. No. 4,524,050 (Chen et al.) discloses a process for hydrolyzing COS in gas streams to H₂S and CO₂ using solid supported bicyclo tertiary amine catalyst.

U.S. Pat. No. 4,504,449 (Doerges et al.) discloses a process for selective removal of H₂S and possibly COS from a CO₂ containing gas stream using highly volatile secondary amines in an organic solvent. A complex regeneration scheme is required. Applicable secondary amines are diethyl amine, diisopropyl amine, methyl isopropyl amine, ethyl isopropyl amine, dipropyl amine, methyl n-butylamine, methyl isobutyl amine and methyl sec-butyl amine. Applicable organic solvents include alkylated polyethylene glycol ethers, tetrahydrothiophene dioxide etc.

U.S. Pat. No. 4,532,116 (Doerges et al.) discloses a process for the removal of H₂S and/or COS from synthesis gas using at least one secondary amine and an organic solvent. Although the process is selective for H₂S and COS in the presence of CO₂, the process is complex. Two scrubbing zones are required—a preliminary desulfurizing zone using a conventional circulated and regenerated solution and a fine desulfurizing or scrubbing zone using unregenerated solvent. The fine desulfurizing zone contains a heat exchanger to condense the unregenerated solvent. Applicable organic solvents are methanol, ethanol and isopropanol. Applicable secondary amines are N-ethylethaneamine, N-(1-methylethyl)propaneamine, N-methyl-2-propanamine, N-ethyl-2-propanamine, N-propyl-1-propanamine, N-methyl-1-butanamine, N-2-dimethyl-1-propanamine, N-methyl-2-butanamine.

U.S. Pat. No. 4,749,555 (Bush) discloses a process for selective removal of H₂S and COS without absorbing CO₂ from a gas stream having a relatively large concentration of CO₂ using bridgehead amines (bicyclotertiary amine or bicyclo amidine), tertiary amine, physical solvent and water. Applicable physical solvents include sulfolane, polyethylene glycol dimethyl ethers and others.

U.S. Pat. No. 4,980,140 (Souby) discloses a process for selective removal of COS from H₂S using a solvent comprising a tertiary amine, a physical co-solvent and a minor amount of water. The useful physical co-solvent includes sulfones, sulfoxides, glycols and the mono and diethers thereof, 1,3-dioxo heterocyclic compounds (dioxane and dioxolane), aromatic ethers, aromatic hydrocarbons and N-alkylated lactams of gamma or omega amino acids.

U.S. Pat. No. 5,413,627 (Landeck et al.) discloses the selective removal of H₂S and COS from CO₂ using a physical scrubbing agent comprising a heterocycle having five or more ring atoms, which contains two heteroatoms, one of which is nitrogen and the other of which is oxygen or nitrogen. The nitrogen atom present in the ring is/are either double bonded or single bonded but, if single bonded, the nitrogen is organo-substituted. A wide variety of scrubbing agents are disclosed, including 1,3-dimethyl-3,4,5,6-tetrahydro-2(1H)-pyrimidinone (DMTP).

U.S. Pat. No. 5,589,149 (Garland et al.) discloses absorption solvents for removing mercaptans from gas streams without the use of iodine. The solvent comprises alkyl ether of a polyalkylene glycol and a secondary monoalkanolamine and, optionally, other amines, such as dialkanolamines.

U.S. Pat. No. 6,277,345 B1 (Stankowiak et al.) discloses the use of absorption liquid comprising at least one dialkanolamine, at least one polyalkylene glycol alkyl ether, and water for nonselective removal of CO₂, H₂S, COS and other acidic gases from a gaseous stream.

U.S. Pat. No. 6,102,987 (Gross et al.) discloses a process for removal of CO₂ and sulfur compounds from natural gas and raw synthesis gas with a mixture of N-formylmorpholine and N-acetylmorpholine at temperatures between −20° C. and +40° C. at pressure of 10 to 150 bar in absorbing operation.

There is still a need in the industry for an improved composition for selective removal of COS from gaseous streams containing COS and CO₂. It has now been surprisingly and unforeseeably found out that the addition of a primary alkanolamine, secondary alkanolamine or piperazine compound to a polyalkylene glycol alkyl ether or 1,3-dimethyl-3,4,5,6-tetrahydro-2(1H)-pyrimidinone (DMPT) results in selective removal of COS from the gaseous streams containing same with minimal removal of CO₂.

One aspect of the present invention concerns a solvent composition for removal of COS from a gas stream containing same, said composition comprising

-   -   a) at least one polyalkylene glycol alkyl ether of the formula         R₁O—(Alk-O)_(n)—R₂  (I)     -    wherein R₁ is an alkyl group having from 1 to 6 carbon atoms;         R₂ is hydrogen or an alkyl group having from 1 to 4 carbon         atoms; Alk is an alkylene group, branched or unbranched, having         from 2 to 4 carbon atoms, and n is from 1 to 10; and     -   b) at least one alkanolamine compound of the formula         R₃NHR₄OR₆  (II)     -    or at least one piperazine compound of formula

-   -    wherein R₃ is hydrogen, an alkyl group having from 1 to 6         carbon atoms, or the R₄OH group; R₄ is a branched or unbranched         alkylene group having from 1 to 6 carbon atoms; R₅,         independently in each occurrence, is hydrogen or an hydroxyalkyl         group having from 1 to 4 carbon atoms; and R₆ is hydrogen, an         alkyl group having from 1 to 6 carbon atoms or an hydroxyalkyl         group having from 1 to 4 carbon atoms.

Another aspect the present invention concerns a solvent composition for removal of COS from a gas stream containing same, said composition comprising

-   -   a) 1,3-dimethyl-3,4,5,6-tetrahydro-2(1H)-pyrimidinone; and     -   b) at least one alkanolamine compound of the formula         R₃NHR₄OR₆  (II)     -    or at least one piperazine compound of formula

-   -    wherein R₃ is hydrogen, an alkyl group having from 1 to 6         carbon atoms, or the R₄OH group; R₄ is a branched or unbranched         alkylene group having from 1 to 6 carbon atoms; R₅,         independently in each occurrence, is hydrogen or an hydroxyalkyl         group having from 1 to 4 carbon atoms; and R₆ is hydrogen, an         alkyl group having from 1 to 6 carbon atoms or an hydroxyalkyl         group having from 1 to 4 carbon atoms.

In another aspect, the present invention concerns a process for selective removal of COS from a gas stream containing same, said process comprising treating the gas stream with a solvent composition comprising

-   -   a) at least one polyalkylene glycol alkyl ether of the formula         R₁O—(Alk-O)_(n)—R₂  (I)     -    wherein R₁ is an alkyl group having from 1 to 6 carbon atoms;         R₂ is hydrogen or an alkyl group having from 1 to 4 carbon         atoms; Alk is an alkylene group, branched or unbranched, having         from 2 to 4 carbon atoms; and n is from 1 to 10; and     -   b) at least one alkanolamine compound of the formula         R₃NHR₄OR₆  (II)     -    or at least one piperazine compound of formula

-   -    wherein R₃ is hydrogen, an alkyl group having from 1 to 6         carbon atoms, or the R₄OH group; R₄ is a branched or unbranched         alkylene group having from 1 to 6 carbon atoms; R₅,         independently in each occurrence, is hydrogen or an hydroxyalkyl         group having from 1 to 4 carbon atoms; and R₆ is hydrogen, an         alkyl group having from 1 to 6 carbon atoms or an hydroxyalkyl         group having from 1 to 4 carbon atoms.

Still in another aspect, the present invention concerns a process for selective removal of COS from a gas stream containing same, said process comprising treating the gas stream with a solvent composition comprising

-   -   a) 1,3-dimethyl-3,4,5,6-tetrahydro-2(1H)-pyrimidinone; and     -   b) at least one alkanolamine compound of the formula         R₃NHR₄OR₆  (II)     -    or at least one piperazine compound of formula

-   -    wherein R₃ is hydrogen, an alkyl group having from 1 to 6         carbon atoms, or the R₄OH group; R₄ is a branched or unbranched         alkylene group having from 1 to 6 carbon atoms; R₅,         independently in each occurrence, is hydrogen or an hydroxyalkyl         group having from 1 to 4 carbon atoms; and R₆ is hydrogen, an         alkyl group having from 1 to 6 carbon atoms or an hydroxyalkyl         group having from 1 to 4 carbon atoms.

Still in another aspect, the present invention concerns a solvent composition for removal of COS from a gas stream containing same, said composition comprising

-   -   a) a mixture of N-formylmorpholine and N-acetylmorpholine; and     -   b) at least one alkanolamine compound of the formula         R₃NHR₄OR₆  (I)     -    or at least one piperazine compound of formula

-   -    wherein R₃ is hydrogen, an alkyl group having from 1 to 6         carbon atoms, or the R₄OH group; R₄ is a branched or unbranched         alkylene group having from 1 to 6 carbon atoms; R₅,         independently in each occurrence, is hydrogen or an hydroxyalkyl         group having from 1 to 4 carbon atoms; and R₆ is hydrogen, an         alkyl group having from 1 to 6 carbon atoms or an hydroxyalkyl         group having from 1 to 4 carbon atoms.

Still in another aspect, the present invention concerns a process for selective removal of COS from a gas stream containing same, said process comprising treating the gas stream with a solvent composition comprising

-   -   a) a mixture of N-formylmorpholine and N-acetylmorpholine; and     -   b) at least one alkanolamine compound of the formula         R₃NHR₄OR₆  (II)     -    or at least one piperazine compound of formula

-   -    wherein R₃ is hydrogen, an alkyl group having from 1 to 6         carbon atoms, or the R₄OH group; R₄ is a branched or unbranched         alkylene group having from 1 to 6 carbon atoms; R₅,         independently in each occurrence, is hydrogen or an hydroxyalkyl         group having from 1 to 4 carbon atoms; and R₆ is hydrogen, an         alkyl group having from 1 to 6 carbon atoms or an hydroxyalkyl         group having from 1 to 4 carbon atoms.

As used herein, the terms “gas”, “acid gas”, and “gaseous stream” are intended to refer to natural gas, hydrocarbon gas, synthesis gas, steam reformer-type gases, and any other gas containing COS, CO₂ and other gaseous components such as hydrogen sulfide, methane, ethane, propane, hydrogen, carbon monoxide, mercaptans etc. The expression “minimal additional removal of CO₂” means additional CO₂ absorption due to the presence of the amine additive is less than one third of the CO₂ present in the feed gas, all other factors being the same.

In accordance with the present invention, it has been surprisingly discovered that the solvent compositions of the present invention have excellent selectivity for the removal of COS from a gaseous stream containing same with minimal additional removal of CO₂.

It was completely surprising and unexpected to find out addition of an alkanolamine compound of formula II above or a piperazine compound of formula III above to least one polyalkylene glycol alkyl ether of the formula I above, and in particular to a mixture of polyalkylene glycol ethers of formula I above, such as the SELEXOL™ solvent, removes substantially more of the COS present in the gaseous streams with minimal additional removal of CO₂.

It was also equally surprising and unexpected to find out that the addition of an alkanolamine compound of formula II above or a piperazine compound of formula III above to 1,3-dimethyl-3,4,5,6-tetrahydro-2(1H)-pyrimidinone removes substantially more of COS present in the gaseous streams with minimal additional removal of CO₂

Polyalkylene alkyl ethers of formula I suitable in the practice of the present invention are well known and include, without any limitation, diethylene glycol dimethyl ether, diethylene glycol diisopropyl ether, triethylene glycol dimethyl ether, triethylene glycol diisopropyl ether, tetraethylene glycol dimethyl ether, tetraethylene glycol diisopropyl ether, pentaethylene glycol dimethyl ether, pentaethylene glycol diisopropyl ether, hexaethylene glycol dimethyl ether, hexaethylene glycol diisopropyl ether, heptaethylene glycol dimethyl ether, octaethylene glycol dimethyl ether, nonaethylene glycol dimethyl ether, decaethylene glycol dimethyl ether, and any mixture thereof.

Preferred polyethylene glycol alkyl ether is a mixture consisting of a dimethyl ethers of polyethylene glycols of formula CH₃O(C₂H₄O)_(n)CH₃ wherein n is from 2 to 10. Particularly preferred polyethylene glycol alkyl ether is the mixture of dimethyl ethers of polyethylene glycols sold under the trademark SELEXOL by Union Carbide Corporation. SELEXOL™ solvent is a mixture of dimethyl ethers of polyethylene glycols comprising from 0 to 0.5 wt percent of diethylene glycol dimethyl ether, from 5 to 7 wt percent of triethylene glycol dimethyl ether, from 16 to 18 wt percent tetraethylene glycol dimethyl ether, from 23 to 25 wt percent of pentethylene glycol dimethyl ether, from 22 to 24 wt percent of hexaethylene glycol dimethyl ether, from 15 to 17 wt percent of heptaethylene glycol dimethyl ether, from 8 to 10 wt percent of octaethylene glycol dimethyl ether, from 3 to 5 wt percent of nonaethylene glycol dimethyl ether, and from 1 to 2 wt percent of decaethylene glycol dimethyl ether. SELEXOL™ solvent is widely used in gas treating applications for the removal of acidic gases. However, it is known that the removal of COS by the SELEXOL™ solvent is poor due to solvent factors (low solubility) and applications specific factors (low COS partial pressure). Certain amine additives such as bicyclic tertiary amines and tertiary amines have been used, with some success, to improve removal of COS by SELEXOL™ solvent. It has now been discovered that the SELEXOL™ solvent containing alkanolamines of formula II hereinbefore or a piperazine compound of formula m hereinabove is surprisingly selective in removing COS in the presence of CO₂ from gases.

Alkanolamine compounds of formula II useful in the practice of the present invention are well known compounds and include both primary and secondary alkanolamines. Preferred alkanolamine compounds of formula II are primary alkanolamines. Non-limiting examples of alkanolamine compounds are monoethanolamine (MEA), diethanolamine (DEA), methylethanolamine (NMEA), diisopropanolamine (DIPA), and 2-(2-aminoethoxy)ethanol (AEE) also known as diethylene glycolamine (available from Huntsman Corporation under the trademark DGA).

The present invention is particularly useful in the desulfurization portion of an Integrated Combined Cycle Gasification (IGCC) process using an IGCC system consisting of a conventional SELEXOL™ solvent acid gas removal unit, a fixed bed catalytic converter for reducing the gas phase concentration of carbonyl sulfide (COS), and heat exchanger equipment upstream of the SELEXOL™ solvent unit. It has been surprisingly found out that the addition of the alkanolamine compound of formula II above to the SELEXOL™ solvent results in selective removal of COS from the gas feed in the presence of CO₂ with minimal removal of CO₂. The costs associated with the fixed bed catalytic converter are also significantly reduced.

Since the process of the present invention for selective removal of COS from gaseous streams is conducted in the desulfurization portion of an Integrated Combined Cycle Gasification (IGCC) process, the operating conditions of the process are those of the IGCC process. These operating conditions are well known to a person of an ordinary skill in the art.

All parts, percentages and ratios herein are by weight unless otherwise indicated.

The invention will be further clarified by a consideration of the following examples that are intended to be purely exemplary of the present invention and not limiting in any way.

The following components are employed in the examples.

-   -   MEA is monoethanolamine;     -   DEA is diethanolamine;     -   TEA is triethanolamine;     -   NMEA is methylethanoalmine;     -   DIPA is diisopropanolamine;     -   HEP is hydroxyethylpiperazine;     -   MDEA is methyldiethanolamine;     -   DMEA is dimethyethanolamine;     -   DBU is 1,8-diazabicyclo[5.4.0]undec-7-ene;     -   DBN is 1,5-diazabicyclo[4.3.0]non-5-ene;     -   DABCO is 1,4-diazabicyclo[2.2.2]octane, sold by Air Products and         Chemicals, Inc. under the trademark DABCO;     -   DMTP is 1,3-dimethyl-3,4,5,6-tetrahydro-2(1H)-pyrimidinone;     -   Quinuclidine is 1,4-ethanolpiperidine; and     -   AEE is 2-(2-aminoethoxy)ethanol.

EXAMPLES 1 TO 10 AND COMPARATIVE EXAMPLES 1 TO 12

The performance of SELEXOL™ solvent alone, and the mixture of SELEXOL™ solvent and prior art additives were evaluated in a bench scale glass absorber-stripper apparatus with the following characteristics:

-   -   a) standard gas feed conditions (10 mole percent CO2, 1.6 mole         percent COS, and the balance nitrogen, about 3 L/min, 80° F.),     -   b) standard liquid feed conditions (about 11 cc/min, 80° F.),     -   c) standard amount of absorber and stripper staging (small         trays, 25 absorber, 20 stripper),     -   d) approximately standard amount of stripping heat duty applied,     -   e) standard amount of the additive used about 3 percent by         weight),     -   f) gas phase analysis by gas chromatography, liquid phase water         content by Karl Fisher method,     -   g) careful attention to ensuring steady state operation,     -   h) liquid phase COS content was not measured, and     -   i) stripper overhead not sampled for COS or H₂S.

The results obtained in the performance evaluation of different gas treating solvent are provided in Tables below.

TABLE 1 Evaluation of Prior Art and Various Additives for Removal of COS by SELEXOL ™ solvent COS CO₂ Absorption Absorption (percent of (percent of Solvent feed) feed) SELEXOL ™ solvent* 0.7 0.7 SELEXOL ™ solvent* 1.2 0.2 S + 3 wt percent 1,4 2.6 0.0 diazabicyclo[2.2.2]octane (DABCO)* S + 3 wt percent quinuclidine* 5.1 −0.2 S + 3 wt percent 3.1 −0.6 1,5-diazabicyclo[4.3.0]non-5- ene (DBN)* S + 3 wt percent 2.5 0.5 1,8-diazabicyclo[5.4.0]undec- 7-ene (DBU)* S + 3 wt percent triethanolamine 2.0 0.5 (TEA)* S + 3 wt percent triethanolamine −0.7 2.7 (TEA)* S + 3 wt percent methyldiethanol- 1.3 1.3 amine (MDEA)* S + 3 wt percent dimethylethanol- 2.0 0.0 amine (MDEA)* S + 3 wt percent hydroxyethylpi- 17.1 0.7 perazine (HEP) S + 3 wt percent diisopropanol- 18.9 1.0 amine (DIPA) S + 3 wt percent diethanolamine 18.9 2.8 (DEA) S + 3 wt percent diethanolamine 28.3 0.1 (DEA) S + 3 wt percent monoethanol- 28.3 −0.7 amine (MEA) S + 3 wt percent piperazine 29.1 0.8 S + 3 wt percent methylethanol- 6.6 −0.6 amine (NMEA)** S + 3 wt percent methylethanol- 52.1 0.9 amine (NMEA) S + 3 wt percent methylethanol- 50.3 1.1 amine (NMEA) DMTP* 5.8 −1.0 DMTP* 3.6 −1.1 DMTP + 3 wt percent diethanol- 40.1 0.6 amine *not an Example of the present invention **spurious experimental outcome S = SELEXOL ™ solvent

TABLE 2 Comparative Comparative Comparative Example 1 Example 1 Example 2 Example 2 Example 3 Base Solvent SELEXOL ™ SELEXOL ™ SELEXOL ™ DMTP SELEXOL ™ Solvent Solvent solvent solvent Additive 0 Piperazine NMEA none DBU Additive Concentration (wt percent) 25 3 3 0 3 # Absorber Trays 20 25 25 25 25 # Stripper Trays 20 20 20 20 Total Gas Feed Rate (cc/min) 2997 2996 2995 3026 3008 Feed CO2 (mole percent) 10.09 10.18 10.06 9.64 11.06 Feed COS (mole percent) 1.48 1.51 1.51 1.21 1.63 Sweet CO2 (mole percent) 10.02 10.1 10.12 9.74 11.01 Sweet COS (mole percent) 1.47 1.07 1.41 1.14 1.59 Absorber: Lean H2O content (wt percent) 3.2 4 4.6 7.4 4.3 Lean Solvent Flow (cc/min) 11 11 11 11 11 Lean T (F.) 80.7 78.8 79.8 79.8 80.5 Feed Gas T (F.) 80.8 79.1 79.5 79.3 80.3 Sweet Gas T (F.) 81.6 79.5 80.6 79.8 80.8 Rich T (F.) 79.3 77.6 78.1 77.9 77.1 Absorber P (in H2O) 28 28 28 28 28 Stripper Hot Rich Inlet T (F.) 239.1 220.3 232.5 229.1 231.5 Overhead Vap T (C.) 103 100 103 100 100 Reboiler T (F.) 264.7 258.3 254.6 270.5 259.5 COS Absorption (percent of feed) 0.7 29.1 6.6 5.8 2.5 CO₂ Absorption (percent of feed) 0.7 0.8 −0.6 −1.0 0.5

TABLE 3 Comparative Comparative Example 4 Example 5 Example 3 Base Solvent SELEXOL ™ SELEXOL ™ SELEXOL ™ Solvent Solvent solvent Additive DBN DABCO DEA Additive 3 3 3 Concentration (wt percent) Number of 25 25 25 Absorber Trays Number of 20 20 20 Stripper Trays Total Gas Feed 3000 2999 3004 Rate (cc/min) Feed CO2 (mole 10.9 10.26 10.3 percent) Feed COS (mole 1.6 1.51 1.48 percent) Sweet CO2 (mole 10.97 10.26 10.01 percent) Sweet COS (mole 1.55 1.47 1.2 percent) Absorber: Lean H2O content 4 3.6 4.1 (wt percent) Lean Solvent 11 11 11 Flow (cc/min) Lean T (F.) 80.7 82.3 81.1 Feed Gas T (F.) 80.3 81.8 81 Sweet Gas T (F.) 80.8 82.3 81.6 Rich T (F.) 79.4 79.5 79.8 Absorber P (in 28 28 28 H2O) Stripper: Hot Rich Inlet 227.6 246.5 226.7 T (F.) Overhead Vap 100 102 102 T (C.) Reboiler T (F.) 259.9 260.6 256.1 COS Absorption 3.1 2.6 18.9 (percent of feed) CO₂ Absorption −0.6 0.0 2.8 (percent of feed)

TABLE 4 Comparative Comparative Example 4 Example 6 Example 7 Example 5 Example 6 Base Solvent SELEXOL ™ SELEXOL ™ SELEXOL ™ SELEXOL ™ SELEXOL ™ Solvent solvent solvent solvent solvent Additive MEA Quinuclidine none DEA NMEA Additive Concentration (wt percent) 3 3 0 3 3 Number of Absorber Trays 25 25 25 25 25 Number of Stripper Trays 20 20 20 20 20 Total Gas Feed Rate (cc/min) 2999 2978 2985 2990 3012 Feed CO2 (mole percent) 10.09 10.06 10.13 10.03 10.11 Feed COS (mole percent) 1.8 1.76 1.72 1.7 1.67 Sweet CO2 (mole percent) 10.16 10.08 10.11 10.02 10.02 Sweet COS (mole percent) 1.29 1.67 1.7 1.43 0.8 Absorber Lean H2O content (wt percent) 5.4 4.5 3.7 3.6 4 Lean Solvent Flow (cc/min) 11 11 11 11 11 Lean T (F.) 79.7 80.7 82 83.2 80.9 Feed Gas T (F.) 80.6 79.9 80.5 81.8 83.2 Sweet Gas T (F.) 81.1 81 81.4 83 83.5 Rich T (F.) 78.6 76.7 77.8 80.9 82.5 Absorber P (in H2O) 28 28 28 28 28 Stripper: Hot Rich Inlet T (F.) 222.1 213.8 209.7 207.6 201.2 Overhead Vap T (C.) 109 103 105 101 100 Reboiler T (F.) 246.6 250.2 257.5 256.9 255.1 COS Absorption (percent of feed) 28.3 5.1 1.2 15.9 52.1 CO₂ Absorption (percent of feed) −0.7 −0.2 0.2 0.1 0.9

TABLE 5 Comparative Comparative Example 7 Example 8 Example 89 Example 98 Example 9 Base Solvent SELEXOL ™ SELEXOL ™ DMTP SELEXOL ™ SELEXOL ™ Solvent Solvent Solvent solvent Additive NMEA DIPA none HEP TEA Additive Concentration (wt percent) 3 3 0 3 3 Number of Absorber Trays 25 25 25 25 25 Number of Stripper Trays 20 20 20 20 20 Total Gas Feed Rate (cc/min) 3023 3013 3004 2990 3000 Feed CO2 (mole percent) 10.08 10.08 10.02 10.06 10.01 Feed COS (mole percent) 1.61 1.64 1.67 1.58 1.52 Sweet CO2 (mole percent) 9.97 9.98 10.13 9.99 9.96 Sweet COS (mole percent) 0.8 1.33 1.61 1.31 1.49 Absorber: Lean H2O content (wt percent) 3.7 4 8.2 3.2 3.6 Lean Solvent Flow (cc/min) 11 11 11 11 11 Lean T (F.) 79.4 82.9 82.4 84.2 81 Feed Gas T (F.) 78.4 81.3 81.1 82.4 79.3 Sweet Gas T (F.) 79.4 82.6 82 83.7 80.3 Rich T (F.) 78.3 80.1 79.6 80.2 77.5 Absorber P (in H2O) 28 28 28 28 28 Stripper: Hot Rich Inlet T (F.) 200.2 206.7 198.9 197.5 180.5 Overhead Vap T (C.) 101 100 104 100 101 Reboiler T (F.) 255.6 255.6 271.3 258.4 255.7 COS Absorption (percent of feed) 50.3 18.9 3.6 17.1 2.0 CO₂ Absorption (percent of feed) 1.1 1.0 −1.1 0.7 0.5

TABLE 6 Compar- Compar- Compar- ative ative ative Exam- Exam- Exam- Exam- ple 10 ple 11 ple 10 ple 12 Base Solvent SELE- SELE- DMTP SELE- XOL ™ XOL ™ XOL ™ Solvent Solvent solvent Additive TEA MDEA DEA DMEA Additive 3 3 3 3 Concentration (wt percent) Number of 25 25 25 25 Absorber Trays Number of 20 20 20 20 Stripper Trays Total Gas 3005 2995 2981 2994 Feed Rate (cc/min) Feed CO2 10.17 10.01 10.09 9.95 (mole percent) Feed COS 1.48 1.52 1.52 1.47 (mole percent) Sweet CO2 9.9 9.88 10.03 9.95 (mole percent) Sweet COS 1.49 1.5 0.91 1.44 (mole percent) Absorber: Lean H2O 4.2 3.8 8.6 4 content (wt percent) Lean Solvent 11 11 11 11 Flow (cc/min) Lean T (F.) 82.6 82.6 80 80.3 Feed Gas T 80.4 80.4 79 79.7 (F.) Sweet Gas 81.9 81.8 79.6 81 T (F.) Rich T (F.) 77.8 78.5 79.4 76.9 Absorber P 28 28 28 28 (in H2O) Stripper: Hot Rich 185.2 189.5 182.2 198.3 Inlet T (F.) Overhead 102 108 105 108 Vap T (C.) Reboiler T 256.6 257.6 264.3 253.7 (F.) COS Absorption −0.7 1.3 40.1 2.0 (percent of feed) CO₂ Absorption 2.7 1.3 0.6 0.0 (percent of feed)

As can be seen from the Tables 1-6 hereinabove, certain amine additives of the prior art improve removal of COS without substantially increasing the removal of CO₂. For example, the addition of DABCO, quinuclidine, DBN and DBU to the SELEXOL™ solvent increases the COS removal of to the SELEXOL™ solvent from 1 percent to 2-5 percent.

EXAMPLES 11 TO EXAMPLE 15 AND COMPARATIVE EXAMPLES 13 TO 14

The performance of a physical solvent alone, and the mixture of the physical solvent and prior art additives of the present invention were evaluated in a bench scale glass absorber-stripper apparatus with the following characteristics:

-   -   j) standard gas feed conditions (8.7-10 mole percent CO₂,         1.1-1.5 mole percent COS, and the balance nitrogen, about 3         L/min),     -   k) standard liquid feed conditions (about 11 or 30 cc/min),     -   l) standard amount of absorber and stripper staging (small         trays, 25 absorber, 20 stripper),     -   m) approximately standard amount of stripping heat duty applied,     -   n) standard amount of the additive used about 3 percent by         weight),     -   o) gas phase analysis by gas chromatography, liquid phase water         content by Karl Fisher method,     -   p) careful attention to ensuring steady state operation,     -   q) liquid phase COS content was not measured, and     -   r) stripper overhead not sampled for COS or H₂S.

The results obtained in the performance evaluation of different gas treating solvent are provided in Tables 7 and 8 below.

TABLE 7 Exam- Comparative Exam- ple 12 Exam- Example 13 ple 11 003 ple 13 Base Solvent SELEXOL ™ SELE- SELE- SELE- XOL ™ XOL^( ™) XOL ™ Additive None HEP HEP AEE Additive 0 3 3 3 Concentration (wt percent) # Absorber 25 25 25 25 Trays # Stripper 20 20 20 20 Trays Total Gas 2985 2985 2985 2985 Feed Rate (cc/min) Feed CO₂ 8.65 9.34 9.76 9.75 (mole percent) Feed COS 1.48 1.47 1.44 1.43 (mole percent) Sweet CO₂ 8.65 8.14 8.61 8.36 (mole percent) Sweet COS 1.33 0.52 0.58 0.41 (mole percent) Absorber Lean H₂O 7.2 3.9 6.8 3.9 content (wt percent) Lean Solvent 30 30 30 30 Flow (cc/min) Lean T (F.) 81 85 84 85 Feed Gas T 89 89 89 89 (F)¹ Sweet Gas T 66 72 72 70 (F.) Rich T (F.)² 83 88 88 87 Absorber P 28 28 28 28 (in H₂O) Stripper: Hot Rich 209 203 194 204 Inlet T (F.) Overhead 215 216 215 214 Vapor T (F.) Reboiler T 115 122 118 132 (C.) COS Absorption 10 65 60 71 (percent of feed) CO2 Absorption 0 13 12 14 (percent of feed) ¹measured at outlet of feed gas heater ²measured in pot beneath lowest absorber tray

As can be seen from the Table 7 hereinabove, the SELEXOL™ solvent alone removes about 10 percent of the COS from the feed gas while the addition of about 3 wt percent of HEP or AEE to the SELEXOL™ solvent improves COS removal to 60-70 percent. Removal of CO₂ increases from 0 to 12-14 percent.

TABLE 8 Comparative Exam- Exam- Example 14 ple 14 ple 15 Base Solvent DMTP DMTP DMTP Additive none HEP NMEA Additive Concentration (wt 0 3 3 percent) # Absorber Trays 25 25 25 # Stripper Trays 20 20 20 Total Gas Feed Rate (cc/min) 2985 2985 2985 Feed CO₂ (mole percent) 9.75 9.73 9.66 Feed COS (mole percent) 1.43 1.43 1.42 Sweet CO₂ (mole percent) 9.47 9.14 8.69 Sweet COS (mole percent) 1.31 0.45 0.0 Absorber: Lean H₂O content (wt percent) 9.1 4.9 3.9 Lean Solvent Flow (cc/min) 11 11 11 Lean T (F.) 76 79 82 Feed Gas T (F.)¹ 85 84 77 Sweet Gas T (F.) 71 72 68 Rich T (F.)² 82 83 82 Absorber P (in H₂O) 28 28 28 Stripper: Hot Rich Inlet T (F.) 238 261 244 Overhead Vapor T (F.) 216 212 211 Reboiler T (C.) 129 149 150 COS Absorption (percent of feed) 8 69 100 CO2 Absorption (percent of feed) 3 6 10 ¹measured at outlet of feed gas heater ²measured in pot beneath lowest absorber tray

As can be seen from the Table 8 hereinabove, DMTP solvent alone removes about 8 percent of the COS from the feed gas while the addition of about 3 wt percent of HEP or NMEA to the DMTP solvent improves COS removal to about 69-100 percent. Removal of CO₂ increases from 3 to 6-10 percent.

As can also be seen from the Tables 1-8 hereinabove, all the solvent compositions of the present invention showed a marked improvement in COS removal with minimal additional CO₂ removal. Overall, the solvent compositions of the present invention comprising the SELEXOL™ solvent and the alkanolamine of formula II or piparazine compound of formula III removed COS in an amount of from 17 percent to 52 percent as compared to the SELEXOL™ solvent alone which removed COS in an amount of only about 1 percent. Similarly, the solvent composition of the present invention comprising DMTP and the alkanolamine of formula II removed COS in an amount of 40-100 percent as compared to DMTP alone which removed COS in an amount of from 3-8 percent. Such magnitude of improved removal of COS by the solvent compositions of the present invention is completely unexpected and unpredictable.

Other embodiments of the invention will be apparent to those skilled in the art from a consideration of this specification or practice of the invention disclosed herein. It is intended that the specification and examples be considered as exemplary only, with the true scope and spirit of the invention being indicated by the following claims. 

1. A process for selective removal of COS from a gas stream containing COS and CO₂, said process comprising contacting the gas stream with a solvent composition comprising a) 1,3-dimethyl-3,4,5,6-tetrahydro-2(1H)-pyrimidinone; and b) at least one alkanolamine compound of the formula R₃NHR₄OR₆ (II)  or at least one piperazine compound of formula

 wherein R₃ is hydrogen, an alkyl group having from 1 to 6 carbon atoms, or the R₄OH group; R₄ is a branched or unbranched alkylene group having from 1 to 6 carbon atoms; R₅, independently in each occurrence, is hydrogen or an hydroxyalkyl group having from 1 to 4 carbon atoms; and R₆ is hydrogen, an alkyl group having from 1 to 6 carbon atoms or an hydroxyalkyl group having from 1 to 4 carbon atoms.
 2. The process of claim 1 wherein component b) is an alkanolamine of formula II in which substituent R₃ is hydrogen.
 3. The process of claim 1 wherein component b) is at least one of monoethanolamine, diethanolamine, methylethanolamine, diisopropanolamine, and 2-(2-aminoethoxy) ethanol.
 4. The process of claim 3 wherein component b) is monoethanolamine.
 5. The process of claim 1 wherein component b) is a compound of formula III.
 6. The process of claim 1 wherein the solvent composition contains less than about 8.6 weight percent of water. 